1. Field of the Invention
The present invention generally relates to a logging-while-drilling (LWD) tool that measures the resistivity of formations adjacent the wellbore. More particularly, the present invention relates to an LWD resistivity tool with multiple transmitters operating at multiple frequencies in an asymmetric configuration to provide multiple depths of investigation. Still more particularly, the present invention relates to an LWD resistivity tool that includes a calibrating transmitter that permits phase angle and attenuation corrections to be calculated for the resistivity measurements made during drilling operations.
2. Background of the Invention
Wells are drilled to reach and recover petroleum and other hydrocarbons in subterranean formations. Modern drilling operations demand a great quantity of information relating to the parameters and conditions encountered downhole to permit the driller to change the direction of drilling to find or stay in formations that include sufficient quantities of hydrocarbons. Such information typically includes characteristics of the earth formations traversed by the wellbore, in addition to data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as "logging," can be performed by several methods.
Logging has been known in the industry for many years as a technique for providing information regarding the particular earth formation being drilled. In conventional oil well wireline logging, a probe or "sonde" is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The sonde may include one or more sensors to measure parameters downhole and typically is constructed as a hermetically sealed steel cylinder for housing the sensors, which hangs at the end of a long cable or "wireline." The cable or wireline provides mechanical support to the sonde and also provides an electrical connection between the sensors and associated instrumentation within the sonde, and electrical equipment located at the surface of the well. Normally, the cable supplies operating power to the sonde and is used as an electrical conductor to transmit information signals from the sonde to the surface, and control signals from the surface to the sonde. In accordance with conventional techniques, various parameters of the earth's formations are measured and correlated with the position of the sonde in the borehole, as the sonde is pulled uphole.
While wireline logging is useful in assimilating information relating to formations downhole, it nonetheless has certain disadvantages. For example, before the wireline logging tool can be run in the wellbore, the drillstring and bottomhole assembly first must be removed or "tripped" from the borehole, resulting in considerable cost and loss of drilling time for the driller (who typically is paying daily fees for the rental of drilling equipment). In addition, because wireline tools are unable to collect data during the actual drilling operation, the drilling service company must at times make decisions (such as the direction to drill, etc.) possibly without sufficient information, or else incur the cost of tripping the drillstring to run a logging tool to gather more information relating to conditions downhole. In addition, because wireline logging occurs a relatively long period after the wellbore is drilled, the accuracy of the wireline measurement can be compromised. As one skilled in the art will understand, the wellbore conditions tend to degrade as drilling fluids invade the formation in the vicinity of the wellbore. Consequently, a resistivity tool run one or more days after a borehole section has been drilled may produce measurements that are influenced by the resistivity of the mud that has invaded the formation. In addition, the shape of the borehole may begin to degrade, reducing the accuracy of the measurements. Thus, generally, the sooner the formation conditions can be measured, the more accurate the reading is likely to be. Moreover, in certain wells, such as horizontal wells, wireline tools cannot run.
Because of these limitations associated with wireline logging, there is an increasing emphasis on developing tools that can collect data during the drilling process itself. By collecting and processing data and transmitting it to the surface real-time while drilling the well, the driller can more accurately analyze the surrounding formation, and also can make modifications or corrections, as necessary, to optimize drilling performance. With a steerable system the driller may change the direction in which the drill bit is headed. By detecting the adjacent bed boundaries, adjustments can be made to keep the drill bit in an oil bearing layer or region. Moreover, the measurement of formation parameters during drilling, and hopefully before invasion of the formation, increases the usefulness of the measured data. Further, making formation and borehole measurements during drilling can save the additional rig time which otherwise would be required to run a wireline logging tool.
Designs for measuring conditions downhole and the movement and the location of the drilling assembly, contemporaneously with the drilling of the well, have come to be known as "measurement-while-drilling" techniques, or "MWD." Similar techniques, concentrating more on the measurement of formation parameters of the type associated with wireline tools, commonly have been referred to as "logging while drilling" techniques, or "LWD." While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term LWD will be used generically with the understanding that the term encompasses systems that collect formation parameter information either alone or in combination with the collection of information relating to the position of the drilling assembly.
Ordinarily, a well is drilled vertically for at least a portion of its final depth. The layers or strata that make up the earth's crust are generally substantially horizontal. Therefore, during vertical drilling, the well is substantially perpendicular to the geological formations through which it passes. In certain applications, however, such as when drilling from an off-shore platform, or when drilling through formations in which the reservoir boundaries extend horizontally, it is desirable to drill wells that are oriented more horizontally. When drilling horizontally, it is desirable to maintain the well bore in the pay zone (the formation which contains hydrocarbons) as much as possible so as to maximize the recovery. This can be difficult since formations may dip or divert. Thus, while attempting to drill and maintain the well bore within a particular formation, the drill bit may approach a bed boundary. Many in the industry have noted the desirability of an LWD system that could be especially used to detect bed boundaries and to provide real-time data to the driller to enable the driller to make directional corrections to stay in the pay zone. Alternatively, the LWD system could be used as part of a "Smart" system to automatically maintain the drill bit in the pay zone. See, e.g. commonly assigned U.S. Pat. No. 5,332,048, the teachings of which are incorporated by reference herein. The use of an LWD system with these other systems makes it possible to conduct at least certain portions of drilling automatically.
The measurement of formation properties during drilling of the well by LWD systems thus improves the timeliness of measurement data and, consequently, increases the efficiency of drilling operations. Typically, LWD measurements are used to provide information regarding the particular formation through which the borehole crosses. Currently, logging sensors or tools that commonly are used as part of either a wireline or an LWD system include resistivity tools. For a formation to contain hydrocarbons and permit the hydrocarbons to flow through it, the rock comprising the formation must have certain well known physical characteristics. One characteristic is that the formation has a certain measurable resistivity (the inverse of conductivity), which can be determined by an electromagnetic wave, of a particular frequency, that travels through the formation. As will be apparent to one skilled in the art, a wave traveling from point A to point B is attenuated and its phase is shifted proportionally to the conductivity of the media in which it travels. Analysis of this attenuation and phase shift provides the resistivity of the formation surrounding the resistivity tool, which then can be used in combination with other measurements to predict whether the formation will produce hydrocarbons. A sudden measured change in resistivity at the boundary between beds of shale and sandstone can be used to locate these boundaries. In horizontal drilling, the drill bit preferably can then be steered to avoid this boundary and keep the wellbore inside the oil-producing bed. However, to accomplish this detection reliably, a great deal of data is required from the resistivity tool.
Generally speaking, it is desirable for the resistivity tool to measure at multiple depths into the formation around the borehole between the transmitter and receiver pair. Referring to FIG. 1, the first and closest diameter of investigation relative to the resistivity tool is the area within the wellbore through which drilling mud flows back to the surface. If the resistivity of this area is measured inside the wellbore (around the tool itself), a resistivity value will be obtained that generally approximates the resistivity of the drilling mud, R.sub.m. This diameter of investigation can be referred to as D.sub.m, to denote that this is the depth of investigation that will produce a resistivity reading of the drilling mud. The next general area of investigation is the region within the surrounding formation that has been invaded by the drilling mud. This diameter of investigation can be referred to as D.sub.i, because a resistivity measurement in this region will produce a resistivity value of approximately R.sub.xo, which is the resistivity of the invaded zone. The third region of investigation for a resistivity tool, is the formation which has not been invaded by drilling mud. A resistivity measurement of this region will yield the true resistivity value of the formation, R.sub.t. As one skilled in the art will understand, the diameters of investigation, D.sub.m and D.sub.i will vary depending upon many factors, including the position of the tool in the wellbore, the characteristics of the formation and the drilling mud, the time that has elapsed from when that portion of the wellbore was drilled, and the like. While information regarding R.sub.m and R.sub.xo are useful for purposes of evaluation, one of the goals of the resistivity tool is to measure the true formation resistivity, R.sub.t. Thus, it is important to design the resistivity tool to have a sufficient depths of investigation to measure this resistivity.
Resistivity tools have undergone a substantial evolution in order to obtain more resistivity data. FIG. 2 shows a prior art resistivity tool that forms part of a bottomhole assembly. Above the bottomhole assembly, a drill string couples the bottomhole assembly to the structure at the surface of the well. The bottomhole assembly includes a drill bit that drills into the formation. A sensor sub is positioned at some location above the bit, and measures various information regarding the formation and the position of the bottomhole assembly. The sensor sub typically includes a resistivity tool capable of measuring the resistivity in the region around the borehole. The resistivity tool includes a transmitting loop antenna T.sub.x that transmits electromagnetic signals into the formation. The resistivity tool also includes a pair of loop antennas, R.sub.1 and R.sub.2, positioned a predetermined distance from the transmitter. Transmitter T.sub.x generates an electromagnetic (EM) wave at a selected frequency that is received at receivers R.sub.1 and R.sub.2 after traveling through the formation.
The placement of the transmitters with respect to the receiver, and the frequency selected for the EM wave depends on certain criteria. On the one hand, as the transmitter T is placed further away from the receiver pair R.sub.1 and R.sub.2, the attenuation of the transmitted wave becomes more severe. To compensate, the transmitter may use more power to generate a stronger signal that can be detected by the receiver pair. Because lower frequency signals attenuate more slowly than do high frequency signals, use of lower frequency signals can reduce the attenuation of the signal. Unfortunately, lower frequency signals provide less resolution regarding the formation bed boundaries than do high frequency signals. Yet another consideration is that lower frequency signals tend to propagate further into the formation, thus providing a potentially greater depth of investigation for the resistivity measurement. On the other hand, as the transmitter T.sub.x is placed closer to the receiver pair, R.sub.1 and R.sub.2, phase shift and attenuation become harder to detect. A higher frequency signal makes this detection easier. Thus, generally, lower frequency signals tend to be preferred as the distance between the transmitter and receiver pair increases, and higher frequency signals tend to be preferred as the distance decreases between the transmitter and the receiver pair.
The signals detected at the two receivers, R.sub.1 and R.sub.2, will of course differ because the distance between R.sub.2 and transmitter T.sub.x is greater than the distance between R.sub.1 and transmitter T.sub.x. As one skilled in the art will understand, the ratio of the voltage received at R.sub.1 and R.sub.2 thus can be used to establish the attenuation ratio and phase shift difference of the transmitted EM wave that traveled through the formation of interest. This effectively produces a measurement at the point in the middle of the two receivers. The signal received at receiver R.sub.1 can be expressed as A.sub.1 e.sup.j.phi.1, where A.sub.1 represents the amplitude of the signal received at receiver R.sub.1, and .phi..sub.1 represents the phase. Similarly, the signal received at receiver R.sub.2 can be expressed as A.sub.2 e.sup.j.phi.2, where A.sub.2 represents the amplitude of the signal received at receiver R.sub.2, and .phi..sub.2 represents the phase. The ratio of the voltage, R2/R1=A.sub.2 /A.sub.1 e.sup.(j.phi.2-.phi.1), where A.sub.2 /A.sub.1 is the attenuation ratio and (.phi..sub.2 -.phi..sub.1) is the phase difference. Based upon the attenuation and phase shift measurements, an estimate of the resistivity can be made.
Improvements to this relatively simplistic design have been made over the years to produce more data regarding the formation, and to improve the quality of the data that is derived. For example, FIG. 3 shows a prior art resistivity tool with three transmitters T.sub.1, T.sub.2, and T.sub.3, in addition to a pair of receivers, R.sub.1 and R.sub.2. The inclusion of two additional transmitters provides more resistivity data. In addition, because of the different spacing of the transmitters with respect to the receivers, the signals generated by each of the transmitters tends to traverse a different path to the receiver pair. The net effect of this spacing, therefore, is that the signal transmitted by the transmitter furthest from the receiver pair tends to travel more deeply into the formation. Thus, the different transmitters produce different depths of investigation of the formation. The transmitters are activated in a multiplexing fashion, so that each transmitter individually fires, thereby permitting the receivers to identify the source of the EM signal. Thus, during operation, a single transmitter fires, such as transmitter T.sub.1, sending an EM wave at a particular frequency into the formation. The wave is then received at receivers R.sub.1 and R.sub.2, and an attenuation and phase shift measurement can be determined for that transmitter. Transmitter T.sub.2 then fires at the same frequency, and an attenuation and phase shift is measured for that transmitter. Finally, transmitter T.sub.3 fires, and an attenuation and phase shift measurement is made with respect to that transmitter. Each firing results in readings at the two receivers, R.sub.1 and R.sub.2. Multiple readings at the receivers result in multiple measurements of phase shift and attenuation of the signals. Consequently, a more accurate resistivity profile can be obtained, with multiple depths of investigation.
FIG. 4 shows a prior art resistivity tool with four transmitters T.sub.1, T.sub.2, T.sub.3, and T.sub.4, in addition to a pair of receivers, R.sub.1 and R.sub.2. See M. S. Bittar, et al., "A True Multiple Depth of Investigation Electromagnetic Wave Resistivity Sensor: Theory, Experiment and Prototype Field Test Results," presented at the 66.sup.th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers on Oct. 6-9, 1991; S. Ball, et al., "Formation Evaluation Utilizing a New MWD Multiple Depth of Investigation Resistivity Sensor," presented at the Fifteenth European Formation Evaluation Symposium on May 5-7, 1993. As noted above, the greater the distance between a transmitter and a pair of receivers, the greater the depth of investigation into the formation. Thus, the addition of a fourth transmitter results in more data being received at the receivers, and a more accurate profile of resistivity around the well bore. As with the resistivity tool shown in FIG. 3, each transmitter fires sequentially, with attenuation and phase shift measurements being made based on the amplitude and time of the signals received by the receiver pair. Because transmitter T.sub.4 is located further away from the pair of receivers, R.sub.1 and R.sub.2, it has been found advantageous to fire this transmitter at a lower frequency than the other transmitters T.sub.1, T.sub.2, T.sub.3. A lower frequency signal from the transmitter transverses further (or deeper) into the formation than a comparable higher frequency signal, but results in lower vertical resolution. This lower resolution can be a problem, for example, when attempting to recognize the presence of a thin bed. Thus, it is advantageous in this design to utilize two different frequencies for the four transmitters (one frequency for T.sub.1, T.sub.2, T.sub.3, and a lower frequency for T.sub.4). Moreover, the smaller the distance between a transmitter and a pair of receivers, the less the depth of investigation into the formation. Thus, the addition of a fourth transmitter results in more data being received at the receivers, and a more accurate profile of resistivity around the well bore.
One of the problems with using the resistivity tool designs shown in FIGS. 2, 3 and 4 is that the measurements derived by the receivers will include some error components. Some of that error is attributable to the manner in which the receiver circuitry will react in response to the high temperatures encountered downhole. The high temperatures and other environmental obstacles encountered downhole can cause thermal drift of the electronics in the receivers. As one skilled in the art will appreciate, the high temperature affects the response of the circuitry (e.g. resistors, capacitors) in the resistivity tool. Simply put, this means that the two receivers may produce different responses because of the high temperatures in which they operate. Consequently, each resistivity tool must be corrected for thermal drift in some manner to ensure the accuracy of the resistivity measurements. Several correction techniques have developed to address this problem with thermal drift. One technique is to configure the resistivity tool in a compensated design that includes a transmitter array on each side of the receiver pair to produce compensated receiver values. A second technique is to use an asymmetrical transmitter design (as shown for example in FIGS. 2-4), with stored calibration values to correct the receiver measurements for thermal drift.
FIG. 5 shows a prior art resistivity tool with compensation. The resistivity tool in FIG. 5 includes a pair of receivers, R.sub.1 and R.sub.2, and four transmitters T.sub.1, T'.sub.1, T.sub.2 and T'.sub.2. Unlike the tool shown in FIG. 4, the compensated tool of FIG. 5 includes a symmetric pair of transmitters placed on both sides of the receivers, R.sub.1 and R.sub.2. The transmitters, T.sub.1 and T.sub.2, below the receivers are placed the same distance away from the receivers as the transmitters, T.sub.1' and T.sub.2', above the receivers, and thus have the same depth of investigation into the formation. The results from corresponding pairs of transmitters (T.sub.1 /T.sub.1' and T.sub.2 /T.sub.2') may be "averaged" to reduce the effects of electronic component response due to temperature variations. One problem with this arrangement, however, is that only two depths of investigation can be made because effectively only two transmitter spacings are provided. To increase the number of measurements and depths of investigation, each transmitter is fired at two different frequencies. For example, in addition to a 2 MegaHertz (MHz) frequency, the transmitters of this design may fire at 400 kHz. This permits four different depths of investigation into the surrounding formation. To provide additional depths of investigation, more transmitters must be added, extending the length of the tool.
FIG. 6 shows a resistivity tool that attempts to provide additional measurements with "pseudo-compensation." See U.S. Pat. No. 5,594,343. The resistivity tool of FIG. 6 includes a pair of receivers, R.sub.1 and R.sub.2, and a set of transmitters, T.sub.1, T.sub.2, T.sub.3, T.sub.4 and T.sub.5. In this design, only two transmitters, T.sub.2 and T.sub.4, are placed below the receiver pair, whereas there are three transmitters, T.sub.1, T.sub.3 and T.sub.5, above the receiver pair. The location of each transmitter below the receiver pair is determined by placing each transmitter half way between the position transmitters locations that would be used for a fully compensated resistivity tool. One advantage of this design is that more depths of investigation are possible than can be performed in a fully compensated tool. At the same time, this design also achieves some level of compensation, although temperature drift calibration is still required to some extent. However, those skilled in the art still debate whether the benefits in this design outweigh the error that is introduced by having an unbalanced configuration.
As compared to these compensated or pseudo-compensated designs shown in FIGS. 5 and 6, the second correction technique is to calibrate the asymmetrical resistivity tool designs shown in FIGS. 3 and 4 to correct for thermal drift. These designs have the advantage of providing more depths of investigation, since each transmitter provides a different depth of investigation. Thus, the four transmitter design of FIG. 4, for example, measures four depths of investigation. In systems, such as those shown in FIG. 4, the receivers are calibrated to determine the thermal drift of the receivers before the tool is used in an LWD operation. In this calibration process, the resistivity tool is heated to various temperatures, and the receiver response is evaluated. A look-up table is then constructed in memory to identify the thermal drift of the receivers at each temperature. When the tool subsequently is used in an LWD operation, the temperature in the vicinity of the receivers is measured, and the system determines a correction thermal drift value for the measured resistivity values by accessing the calibration look-up table. While this device may overcome the problem with thermal drift, it requires that the receivers be regularly calibrated before being used in the hole for thermal drift. This requires a lengthy calibration process, in which the tool is heated and thermal drift is measured for a range of temperatures. In addition, it is difficult to simulate the conditions encountered in a wellbore, and thus the calibration process may not adequately reflect the actual conditions encountered by the resistivity tool downhole.
It would be desirable if a resistivity tool could be developed that was capable of investigating a sufficient number of depths, while calculating correction values for thermal drift in a real-time or near real-time manner. Despite the apparent advantages that such a system would offer, to date no one has successfully introduced such a system.